Electronically monitoring drilling conditions of a rotating control device during drilling operations

ABSTRACT

In accordance with some embodiments of the present disclosure, a drilling system comprises a rotating control device (RCD). A plurality of sensors included in or in proximity to the RCD are configured to detect drilling conditions associated with the RCD during a drilling operation. A control system is configured to determine an adjustment to a drilling parameter based on the drilling conditions.

PRIORITY CLAIM

This application claims priority under 35 U.S.C. §119 to U.S.Provisional Patent Application Ser. No. 61/747,704 filed Dec. 31, 2012.The content of which is incorporated by reference herein in itsentirety.

TECHNICAL FIELD

The present disclosure relates generally to equipment used andoperations performed in connection with well drilling operations and,more particularly, to electronically monitoring drilling properties of arotating control device during drilling operations.

BACKGROUND

Drilling operations may be performed in a variety of locations andsettings. Some drilling operations may be performed on land, and awellbore may be formed by drilling through rock directly beneath adrilling system. Some drilling operations may be performed offshore, anda wellbore may be formed by first passing through water and thendrilling through the seabed. When drilling, a gap (typically referred toas an annulus) may be present between the drill string and the casingand/or outside of the wellbore. In some drilling operations, the annulusmay be closed during drilling operations. Some closed annulus drillingoperations may include Managed Pressure Drilling (MPD), underbalanceddrilling, mud cap drilling, air drilling, and mist drilling

When performing closed annulus drilling operations, a rotating controldevice (RCD), also referred to as a rotating drilling device, rotatingdrilling head, rotating flow diverter, pressure control device androtating annular, may be used to divert drilling fluids returning fromthe well. The drilling fluids may be diverted into separators, chokesand other equipment. The RCD may function to close off the annulusaround a drill string during drilling operations. The sealing mechanismof the RCD, typically referred to as a seal element or packer, isoperable to maintain a dynamic seal on the annulus. This may enablechokes to control pressure of the annulus at the surface drillingoperations. For example, during underbalanced drilling, there is a netflow out of the drilling fluid from the annulus, creating a backpressure. This flow (and back pressure) may be controllable using chokesplaced at intervals along the annulus in fluid communication with thedrilling fluid. These chokes may be selectively operated from thesurface of the drilling operations. The seal element further allowsdrilling to continue while controlling influx of formation fluids.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and itsfeatures, reference is now made to the following description, taken inconjunction with the accompanying drawings, in which:

FIG. 1 illustrates an example embodiment of a drilling system configuredto perform closed annulus drilling operations in accordance with someembodiments of the present disclosure;

FIG. 2 illustrates a partial cross-sectional view of a rotating controldevice including sensors to measure drilling conditions associated withthe device in accordance with some embodiments of the presentdisclosure;

FIG. 3 illustrates a block diagram of a control system configured toreceive measurements from the sensors associated with the rotatingcontrol device of FIG. 2 in accordance with some embodiments of thepresent disclosure;

FIG. 4 illustrates a flow chart of an example method for monitoringdrilling conditions associated with a rotating control device duringdrilling operations in accordance with some embodiments of the presentdisclosure; and

FIG. 5 illustrates a flow chart of another example method for monitoringdrilling conditions associated with a drilling system in accordance withsome embodiments of the present disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure are best understood by referringto FIGS. 1 through 5, where like numbers are used to indicate like andcorresponding parts.

FIG. 1 illustrates an example embodiment of a drilling system configuredto perform closed annulus drilling operations, in accordance with someembodiments of the present disclosure. During closed annulus drillingoperations, some of which may be referred to as MPD, underbalanceddrilling, mud cap drilling, air drilling and mist drilling, the annulusof the drill string is closed off using a device referred to as arotating control device (RCD), a rotating drilling device, a rotatingdrilling head, a rotating flow diverter, pressure control device or arotating annular. The principle sealing mechanism of the RCD, referredto as a seal element or packer, seals around the drill string, thus,closing the annulus around the drill string. During drilling operations,various drilling conditions may affect the condition and performance ofthe RCD.

As disclosed in further detail below and according to some embodimentsof the present disclosure, different types of sensors may be located inor near the RCD in order to measure drilling conditions associated withthe RCD. The sensors may measure various properties associated with theoperation, maintenance, and/or status of a drilling system (e.g.temperature, pressure, flow rate). For example, the sensors may betemperature and/or pressure transducers, flow meters, thermocouples,proximity sensors (e.g., acoustic, magnetic, laser, etc.), distancesensors, mechanical sensors (e.g., roller, arm, etc. contacting thedrill string), accelerometers and/or strain gauges. These sensors may beused to measure (i) pressure in the standpipe, (ii) pressure and/ortemperature associated with the seal element (e.g., upstream of thechoke or RCD body), (iii) pressure, temperature, flow rate, revolutionsper minute (RPM) and/or vibration associated with the bearing assemblyof the RCD, (iv) pressure, flow rate and location associated with thelatch assembly and (v) stripping rate, rate of penetration (ROP) andjoint count associated with the tool joints of the drill string.Examples of the sensors used in drilling system 100 in accordance withthe present disclosure and the measurements provided by those sensorsmay also be found in Table A. The measurements and/or data generatedfrom these sensors may then be analyzed and used to take various actionsduring drilling operations in order to provide increased safety,reliability and/or usability of the RCD. Examples of how they may beanalyzed and the actions that may be taken based on the measurementsprovided by the sensors may also be found in Table B.

As illustrated in FIG. 1, drilling system 100 may include drilling unit102, drill string 104, rotating control device (RCD) 106, sliding joint108 and riser assembly 110. In the illustrated embodiment, drill string104 may extend from drilling unit 102 through riser assembly 110 andinto a subsea wellbore (not expressly shown) formed in the ocean floor.An upper portion of RCD 106 may be coupled to drilling unit 102 by anabove RCD riser, tie back riser or telescoping joint, where the upperend of the riser or joint may be coupled to a drilling unit diverterhousing (not expressly shown). A seal element or packer (not expresslyshown) may be located within the body of RCD 106 and may be removed orinserted with the aid of latch assembly 103 integral, either internallyor externally, to RCD 106. In some embodiments, latch assembly 103 mayinclude a hydraulic clamp that can be remotely controlled from drillingunit 102. A lower portion of RCD 106 may be coupled to sliding joint108. In one embodiment, sliding joint 108 may be a telescoping jointthat includes an inner barrel and an outer barrel that move relative toeach other in order to allow drilling unit 102 to move during drillingoperations without breaking drill string 104 and/or riser assembly 110.In other embodiments, sliding joint 108 may be a multi-part slidingjoint. Sliding joint 108 may be coupled to riser assembly 110, whichprovides a temporary extension of a subsea wellbore (not expresslyshown) to drilling unit 102.

Drilling unit 102 may be any type of drilling system configured toperform drilling operations. Although FIG. 1 illustrates the use of RCD106 from a floating drilling unit, those skilled in the art willunderstand that RCD 106 can be deployed from any type of onshore oroffshore drilling unit including, but not limited to, Semi Submersible,Drill Ship, Jack Up, Production Platform, Tension Leg Platform and LandDrilling units. In some embodiments, including, but not limited to, LandDrilling units and Jack Up drilling units, a surface blow out preventer(BOP) stack may be incorporated into the drilling system. In theseembodiments, RCD 106 may be coupled to a drilling annular incorporatedin the BOP stack, an operations annular added to the BOP stack anddrilling annular, or directly coupled to the BOP stack. In otherembodiments, RCD 106 may be coupled directly to a wellhead or casinghead for drilling operations prior to the BOP stack being installed.

Drilling unit 102 may include rig floor 112 that is supported by severalsupport structures (not expressly shown). Rotary table 114 may belocated above rig floor 112 and may be coupled to drill string 104 inorder to facilitate the drilling of a wellbore using a drill bit (notexpressly shown) coupled to the opposite end of drill string 104. Drillstring 104 may include several sections of drill pipe that communicatedrilling fluid from drilling unit 102 and provide torque to the drillbit. Drill string 104 may be coupled to standpipe 118 via kelly hose120, both of which may facilitate the flow of drilling fluid into drillstring 104. In some embodiments, standpipe 118 may be a thick metaltubing that is situated vertically along the derrick of drilling system100 and is attached to and supports one end of kelly hose 120. Standpipe118 is further coupled to pump 122 that is used to circulate drillingfluid from tank 124. In the illustrated embodiment, the drilling fluidmay be circulated back to drilling unit 102 through riser assembly 110.In other embodiments, such as a land drilling unit, the drilling fluidmay be circulated through the wellbore or a casing included in thewellbore. Additionally, various cables 116 may couple RCD 106, slipjoint 108 and riser assembly 110 to equipment on drilling unit 102.

A sensor (not expressly shown) may be located in standpipe 118 tomeasure the pressure in standpipe 118. In one embodiment, the sensor maybe a pressure transducer. In other embodiments, a sensor may be a partof a measurement while drilling (MWD) system such that the pressure instandpipe 118 may be derived from software associated with the MWDsystem. For example, a MWD system may be deposited near a drill bit inthe wellbore and may measure various properties related to drillingsystem 100. The pressure in standpipe 118 may indicate whether drillingfluid is being circulated through drill string 104 or if washout orplugging is occurring. For example, a detected pressure greater than apredetermined threshold or a constant pressure over time may indicatethat drilling system 100 is operating normally and drilling fluid isbeing circulated through drill string 104. A detected pressure less thana predetermined threshold or a loss in pressure over time may indicatethat a washout has occurred in drill string 104 or that drill string 104is plugged. If the detected pressure indicates that a washout hasoccurred or drill string 104 is plugged, an alarm may be generated by acontrol system (e.g., the control system as illustrated in FIG. 3) toalert an operator of drilling system 100.

FIG. 2 illustrates a partial cross-sectional view of RCD 106 includingone or more sensors 212 associated with various parts of RCD 106 inaccordance with some embodiments of the present disclosure. RCD 106 maybe used to seal annulus 202 formed radially between body 204 of RCD 106and drill string 104 positioned within body 204. RCD 106 may allow drillstring 104 to rotate and enter and exit the wellbore while maintainingpressure in annulus 202. In the illustrated embodiment, bearing assembly206 may be located in bearing assembly housing 208. One or more sealelements 210 (for example, upper seal element 210A and lower sealelement 210B) may be coupled to body 204 of RCD 106 by a mandrel (notexpressly shown) connected to bearing assembly 206 such that sealelement 210 may rotate with drill string 104. Bearing assembly 206 mayfacilitate the movement of drill string 104 relative to body 204. Inother embodiments, RCD 106 may not include bearing assembly 206 suchthat seal element 210 remains stationary while drill string 104 rotateswithin RCD 106. Latch assembly 103 may be used to secure and releasebearing assembly 206 and seal element 210 relative to body 204.

Seal element 210 may form a seal around drill string 104 to closeannulus 202 and maintain pressure in annulus 202 during drillingoperations. In some embodiments, seal element 210 may be a molded devicemade of an elastomeric material. The elastomeric material may becompounds including, but not limited to, natural rubber, nitrile rubber,hydrogenated nitrile, urethane, polyurethane, fluorocarbon,perflurocarbon, propylene, neoprene, hydrin, etc. Sensors 212 may beassociated with seal element 210 in order to detect various drillingconditions during drilling operations. For example, sensors 212 may belocated in body 204 of RCD 106 below bearing assembly 206 and may beconfigured to detect the pressure and/or temperature associated withseal element 210. Sensors 212 may be pressure or temperature transducersor combination sensors configured to detect both pressure andtemperature. In some embodiments, the pressure and/or temperature ofseal element 210 may additionally be measured by sensors locatedupstream of a choke (not expressly shown) associated with RCD 106. Insome embodiments, sensors 212 may be located within seal element 210.

Sensors 212 may also be associated with bearing assembly 206 andconfigured to measure certain drilling conditions associated withbearing assembly 206. For example, sensors 212 may be located in thecavity of bearing assembly 206, on the mandrel coupling seal element 210to bearing assembly 206, in the seal pressure stages (not expresslyshown) of RCD 106, in the cooling circuits (not expressly shown) of RCD106 and/or in the incoming and return lines (not expressly shown)associated with RCD 106. In some embodiments, sensors 212 associatedwith bearing assembly 206 may be configured to measure the pressureand/or temperature associated with bearing assembly 206 or betweenelements (e.g., the upper stripper and mandrel) in RCD 106. The pressureand/or temperature sensors may be pressure or temperature transducers,thermocouples for measuring temperature or combination sensorsconfigured to measure both pressure and temperature. In otherembodiments, sensors 212 associated with bearing assembly 206 may beflow meters configured to measure flow rates of fluids in bearingassembly 206. In further embodiments, sensors 212 associated withbearing assembly 206 may be proximity sensors located on fixed androtating members of bearing assembly 206. Signals from the proximitysensors may be used to calculate the revolutions per minute (RPM) ofbearing assembly 206 and/or drill string 104. In additional embodiments,sensors 212 associated with bearing assembly 206 may be accelerometersand/or acoustic sensors configured to detect vibration associated withbearing assembly 206 and/or the associated mandrel. In otherembodiments, sensors 212 associated with bearing assembly 206 may bestrain gauges located on the mandrel and used to determine the torqueimparted by a drill pipe/tool joint interface on drill string 104 tobearing assembly 206.

Sensors 212 may also be located inside the mandrel of bearing assembly206, the upper stripper (not expressly shown) of RCD 106, body 204 ofRCD 106, and/or the tieback (not expressly shown) of RCD 106 todetermine various drilling conditions associated with tool joints 214 ofdrill string 104. For example, sensors 212 may be casing collar locators(CCL), proximity sensors (e.g., acoustic, magnetic, laser, etc.),distance sensors and/or mechanical sensors (e.g., a roller or armcontacting drill string 104) configured to sense each time tool joint214 passes through RCD 106. In some embodiments, the signals fromsensors 212 may be used to calculate the stripping rate or rate ofpenetration for tool joint 214.

Sensors 212 may further be associated with latch assembly 103 in orderto determine the status of latch engagement. For example, sensor 212 maybe a flow meter located in a hydraulic circuit (not expressly shown) oflatch assembly 103 to determine the position and engagement of latchassembly 103 based on total flow. In other embodiments, sensor 212 maybe a pressure transducer located in the hydraulic circuit of latchassembly 103 to determine the pressure in latch assembly 103. In furtherembodiments, sensor 212 may be a proximity sensor (e.g., acoustic,magnetic, laser, etc.), a distance sensor, and/or a mechanical sensorconfigured to sense the location of the latch member or piston (notexpressly shown) in latch assembly 103.

Sensors 212 may communicate the measured drilling conditions to acontrol system (such as the control system illustrated in FIG. 3)located on or remote from drilling unit 102 (as illustrated in FIG. 1).As described in more detail in reference to FIG. 3, the control systemmay correlate the drilling condition data to various actions that shouldbe taken during drilling operations, for example, such that a drillingoperator can make a determination of when to replace seal element 210and/or the bearings of bearing assembly 206.

Although FIG. 2 illustrates a particular number and location for sensors212, any number of sensors may be located in various positions in RCD106. Additionally, although certain types of sensors and themeasurements provided by the sensors are described in reference to FIG.2, other sensors and measurements may be provided as described in TablesA and B.

FIG. 3 illustrates a block diagram of a control system configured toreceive measurements from the sensors associated with the standpipe ofFIG. 1 and the rotating control device of FIG. 2 in accordance with someembodiments of the present disclosure. In some embodiments, one or moresensors 212 a-212 i may be associated with drilling system 100 andconfigured to measure any number of drilling conditions associated withRCD 106. As described above and in Table A, sensors 212 may betemperature and/or pressure transducers, flow meters, thermocouples,proximity sensors (e.g., acoustic, magnetic, laser, etc.), distancesensors, mechanical sensors (e.g., roller, arm, etc. contacting thedrill string), accelerometers and/or strain gauges. To the extent any ofsensors 212 require power to operate, sensors 212 may be powered bybattery power, wired power, solar power, or any other power source asmay be appropriate for the location and power demands of sensor 212.

Sensors 212 may be communicatively coupled to input device 302 ofcontrol system 300 such that control system 300 may receive the drillingcondition data and other information measured by sensors 212. Inputdevice 302 may direct the data received from sensors 212 to processingsystem 304. Input device 302 may also be communicatively coupled toother sources of information about drilling system 100 generally, forexample, measurement while drilling (MWD) system 320. Processing system304 may include a processor 312 coupled to a memory 314. Processor 312may include, for example, a microprocessor, microcontroller, digitalsignal processor (DSP), application specific integrated circuit (ASIC),or any other digital or analog circuitry configured to interpret and/orexecute program instructions and/or process data. In some embodiments,processor 312 may interpret and/or execute program instructions and/orprocess data stored in memory 314. Such program instructions or processdata may constitute portions of software for carrying out simulation,monitoring, or control of drilling operations. Memory 314 may includeany system, device, or apparatus configured to hold and/or house one ormore memory modules; for example, memory 314 may include read-onlymemory, random access memory, solid state memory, or disk-based memory.Each memory module may include any system, device or apparatusconfigured to retain program instructions and/or data for a period oftime (e.g., computer-readable non-transitory media). For the purposes ofthis disclosure, computer-readable media may include any instrumentalityor aggregation of instrumentalities that may retain data and/orinstructions for a period of time. Computer-readable media may include,without limitation, storage media such as a direct access storage device(e.g., a hard disk drive or floppy disk), a sequential access storagedevice (e.g., a tape disk drive), compact disk, CD-ROM, DVD, randomaccess memory (RAM), read-only memory (ROM), electrically erasableprogrammable read-only memory (EEPROM), and/or flash memory; as well ascommunications media such as wires, optical fibers, and otherelectromagnetic and/or optical carriers; and/or any combination of theforegoing.

Processing system 304 may also be coupled to a storage device 316.Storage device 316 may include any instrumentality or aggregation ofinstrumentalities that may retain data and/or instructions for a periodof time. Storage device 316 may include, without limitation, storagemedia such as a direct access storage device (e.g., a hard disk drive,optical drive, solid state drive, or floppy disk), a sequential accessstorage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD,random access memory (RAM), read-only memory (ROM), electricallyerasable programmable read-only memory (EEPROM), and/or flash memory, orany combinations thereof. In some embodiments, storage device 316 maystore any of the information handled, processed, reported, produced, orutilized by processing system 304.

In some embodiments, sensors 212 may be communicatively coupled to inputdevice 302 indirectly through a transmitter and/or receiver (not shown).Transmitters and/or receivers may be placed at a variety of locationsthroughout a drilling system (e.g. drilling system 100 illustrated inFIG. 1). For example, transmitters and/or receivers may be placed inproximity to (i) body 204, bearing assembly 206, tie back, and/or upperstripper of RCD 106, (ii) the hydraulic power unit (HPU), (iii) the workplatform, the control console, and/or the rig floor or cantilever deckof the drilling unit (such as drilling unit 102 of FIG. 1), and/or (iv)near the wellhead (e.g. on a BOP stack). In other embodiments, data fromsensors 212 may be communicated through wires, such as electrical wiresor fiber optics. In additional embodiments, communication of thedrilling conditions from sensors 212 may be wireless. For example, thesignals carrying the drilling conditions may be acoustic,electromagnetic or optical. The signals carrying drilling conditions mayalso be transmitted via fluid pulse. The measurements may becommunicated by sensors 212 either continuously or based on apre-determined time interval.

Processing system 304 may be communicatively coupled to display 306 thatis part of control system 300 such that information processed byprocessing system 304 may be conveyed to operators of a drilling system(e.g., drilling system 100 as illustrated in FIG. 1). Display 306 maydisplay various drilling conditions obtained by sensors 212 and/orvalues calculated by processing system 304. Printer 308 and associatedprintouts 308 a may also be used to report the drilling conditionsassociated with RCD 106. Outputs 310 may be communicated to variouscomponents associated with operating the associated drilling system, tovarious remote locations to monitor and/or control the performance ofthe drilling system, or to users simulating the drilling of a wellbore.Outputs 310 may also be communicated to various data storage locations(not expressly shown), either local to the drilling system or remotely,for example, to a facility including various data storage devices.

In some embodiments, in addition to various drilling conditions and/orvalues calculated based on drilling conditions, other informationregarding a drilling system (e.g., drilling system 100 as illustrated inFIG. 1) may be displayed on display 306. Display 306 may display thestatus of a latch assembly (e.g., latch assembly 103 as illustrated inFIG. 1) as a total flow in a hydraulic circuit associated with the latchassembly and the total flow required for engagement of the latchassembly, a graphic of the position of the piston of the latch assemblyand/or the latch assembly, a percentage of actuation of the latchassembly, and/or a Boolean value (e.g. “latched” or “unlatched”).Display 306 may also display status of a cooling system associated withan RCD (e.g., RCD 106 as illustrated in FIGS. 1 and 2). For example,display 306 may display the temperature of a tank of the cooling system,the temperature of outgoing lines, the temperature of the fluid inreturn lines, flow rates of the cooling fluid, whether the cooler fan ison or off, and whether a pump of the cooling system is on or off.Display 306 may also display status of a lubrication system associatedwith the RCD. For example, display 306 may display a pressure set pointand a graph over time of the pressure of the lubrication system and/orthe wellbore over time. As another example, display 306 may also displayan average and/or instantaneous flow rate of fluid in a lubricationsystem, a total flow for a given time period, and/or time until a tankof the lubrication system is empty. Display 306 may also displayparameters associated with the RCD, for example, temperature in abearing assembly (e.g. bearing assembly 206 as illustrated in FIG. 2),pressure in the bearing assembly, and/or pressure between elements (e.g.an upper stripper and a mandrel of the RCD). Display 306 mayadditionally display parameters associated with general operation of thedrilling system, for example, number of hours in the hole (static and/orrotating), number of tool joints passed down hole, wellbore annuluspressure, and/or temperature of wellbore fluid. It will be appreciatedthat display 306 may display any combination of the foregoing, eithersimultaneously or separately in any variation of combinations. Forexample and in no way limiting, display 306 may display all relevantinformation regarding the RCD at once, and then may separately (forexample by a menu selection of control system 300) display informationregarding the cooling and lubrication systems together.

In some embodiments, control system 300 may be configured to receivedrilling conditions associated with standpipe 118 and RCD 106 fromsensors 212 during drilling operations. Processing system 304 mayinterpret the drilling condition data and determine actions to be takenduring drilling operations. For example, the signals from sensors 212may be processed based on scalar functions and/or algorithms used tocalculate various drilling parameters. In some embodiments, temperature,pressure, flow rate, vibration, latch position, torque, and/or anycombination thereof may be processed based on a scalar function. Thedrilling conditions received may include, but are not limited to,pressure, temperature, flow rate, vibration, position, torque, strainand tool joint count as described in Table A. Once the measured drillingconditions are processed into a useable format, processing system 304may analyze the drilling condition data and determine an adjustment toone or more drilling parameters based on the analyzed data that may bemade manually by an operator of drilling system 100 and/or automaticallyby processing system 304.

In one embodiment, processing system 304 may analyze the receiveddrilling condition data by comparing the data to correspondingpre-determined thresholds or trigger points in order to interpret thedata and make a determination of what actions should be taken duringdrilling operations. In other embodiments, processing system 304 maycompare a change in drilling conditions over time to correspondingpre-determined thresholds or trigger points. In further embodiments,processing system 304 may use the detected drilling conditions tocalculate a drilling parameter (e.g. through the use of an algorithm).For example, processing system 304 may use position data from proximitysensors to calculate revolutions per minute (RPM) of bearing assembly206 and/or drill string 104 and tool joint stripping rate or rate ofpenetration (ROP) using an algorithm. Other examples of calculationsthat may be performed by processing system 304 based on the analyzeddata are described in Table B. In some embodiments, an alarm may begenerated by processing system 304 if a drilling condition or otherdetermined value exceeds a pre-determined threshold or trigger point.For some drilling conditions or other determined values, an alarm mayonly be generated if the drilling condition or other determined valueexceeds the pre-determined threshold or trigger point for a specifiedduration of time. In some embodiments, multiple trigger pointsgenerating multiple alarms may be associated with a single drillingcondition or other determined value. For example, if the trigger pointis passed by a first amount, a first alarm may be generated and if thetrigger point is passed be a second further amount, a second more severealarm may be generated.

Processing system 304 may interpret data associated with standpipe 118of drilling system 100 as described in Table B. In this embodiment,sensor 212 may be a pressure transducer configured to measure thepressure in standpipe 118. The pressure in standpipe 118 may be anindication of whether the drilling fluid is circulating through drillstring 104 or whether a washout has occurred in drill string 104 ordrilling string 104 is plugged. If the measured pressure is greater thana pre-determined threshold or the pressure is constant, processingsystem 304 may determine that drilling fluid is circulating normallythrough drill string 104. If the measured pressure is less than apre-determined threshold or the pressure decreased over time, processingsystem 304 may determine that a washout has occurred or drill string 104is plugged and generate an alarm that may be displayed on display 306.

Processing system 304 may also interpret data associated with sealelement 210 of RCD 106 as described in Table B. In this embodiment,sensor 212 may be a pressure or temperature transducer, a thermocouple,and/or a combination sensor configured to measure both pressure andtemperature. The pressure below seal element 210 may be an indication ofwhether it is safe to unlatch RCD 106. For example, if the measuredpressure is approximately equal to zero pounds per square inch (psi),latch assembly 103 of RCD 106 may be safe to unlock and, if the measuredpressure is greater than zero psi, latch assembly 103 of RCD 106 shouldremain locked. Additionally, the pressure below seal element 210 mayindicate what pressure should be applied to the lubrication systemassociated with RCD 106 and what pressure should be applied to an activeelement of RCD 106. The amount of pressure that should be applied to thelubrication system or the active element may be used as an input valueto a formula used to calculate the pressures.

The temperature below seal element 210 may provide an indication of theheat load that is being cooled by the cooling circuit of RCD 106 and mayindicate whether the temperature limits for the materials used for thevarious elements in RCD 106 have been exceeded. For example, if themeasured temperature is greater than a pre-determined threshold, thecooling fluid flow rate may be changed by, for example, opening orclosing the cooling loops in the cooling circuitry of RCD 106 in orderto reduce the temperature. In other embodiments, the coolant fluidcoolers and/or chillers in drilling system 100 may be activated ordeactivated as appropriate.

Processing system 304 may additionally interpret data associated withbearing assembly 206 of RCD 106 as described in Table B. In thisembodiment, sensor 212 may be a pressure or temperature transducer, athermocouple for measuring temperature, a combination sensor configuredto measure both pressure and temperature, a flow meter, a proximitysensor (e.g., acoustic, magnetic, laser, etc.), a distance sensor, amechanical sensor (e.g., roller, arm, etc. contacting drill string), anaccelerometers and/or a strain gauge. In one embodiment, sensor 212 maymeasure the pressure(s) in bearing assembly 206. The pressure in bearingassembly 206 may indicate whether the static seals and other componentsof the lubrication circuit are functioning properly, provide anindication of the lifetime of bearings in bearing assembly 206 andindicate a status of the engagement of latch assembly 103. For example,the detected pressure may indicate the status of a lubrication circuitin bearing assembly 206. If the pressure cannot be maintained at a setpoint, processing system 304 may activate an alarm that is displayed ondisplay 306 to alert the operator of drilling system 100.

In another embodiment, sensor 212 may measure the temperature in bearingassembly 206. The temperature in bearing assembly 206 may provide anindication of whether the temperature limits for the materialsassociated with, for example, seal element 210, are being exceeded. Ifthe measured temperature is outside of a specified range, processingsystem 304 may activate an alarm to alert an operator of drilling system100 that the temperature inside bearing assembly 206 is greater than apre-determined threshold. The measured temperature associated withbearing assembly 206 may also be combined with other sensor measurementsas described in Table B. As one example, processing system 304 may usethe temperature and the pressure associated with bearing assembly 206 tocalculate the estimated lifetime of bearings in bearing assembly 206. Ifthe estimated lifetime is less than a minimum value, processing system304 may generate an alarm that may be displayed on display 306 andalerts an operator of drilling system 100 that the bearings in bearingassembly 206 may have reached their maximum life and should be replaced.Other example adjustments based on the measured pressure and/ortemperature are described in Table B.

In a further embodiment, sensor 212 may measure the flow rate of bearingassembly fluids in bearing assembly 206. The flow rate of the fluids mayindicate if various components of RCD 106 are working properly and/or ifseal element 210 is worn. The flow rates may additionally be used tocalculate the heat that is being transferred to the cooling circuit ofRCD 106 during drilling. For example, processing system 304 may comparethe measured flow rates with pre-determined flow rates that are expectedunder certain conditions. If the flow rates are not within a specifiedrange during a certain time, processing system 304 may generate an alarmto allow an operator of drilling system 100 to adjust any pumps and/orvalves associated with bearing assembly 206 to achieve the set points.In other embodiments, processing system 206 may generate outputs 310 todrilling system 100 so that the pumps and/or valves may be automaticallyadjusted. Other example adjustments based on the measured flow rates aredescribed in Table B.

In an additional embodiment, sensor 212 associated with bearing assembly206 may be a proximity sensor (e.g., acoustic, magnetic, laser, etc.), adistance sensor and/or a mechanical sensor (e.g., roller, arm, etc.contacting drill string). The measurements provided by these types ofsensors may provide a count of the number of tool joints 214 that passthrough RCD 106 during drilling operations and may be used to calculatethe revolutions per minute (RPM) of bearing assembly 206 and/or the RPMof drill string 104. The tool joint count and RPM values may be used toestimate the lifetime of seal element 210 and/or bearing assembly 206.Additionally, the RPM of bearing assembly 206 combined with the RPM ofdrill string 104 may indicate element slippage and whether certainelements, such as seal element 210, are worn. Processing system 304 maycompare the bearing assembly RPM to the drill string RPM. If thedifference between these values is greater than a pre-determinedthreshold for a specified time period, processing system 304 maygenerate an alarm for display on display 306. Other example adjustmentsbased on the measurements provided by proximity sensors, distancesensors and/or mechanical sensors are described in Table B.

In another embodiment, sensor 212 associated with bearing assembly 206may be an accelerometer configured to detect vibration associated withbearing assembly 206. Vibration in bearing assembly 206 may indicatemetal to metal contact between rotating and stationary components andmay be used to estimate the lifetime of bearing assembly 206 and/or sealelement 210. Processing system 304 may compare the measured vibrationwith a pre-determined threshold and may generate an alarm to alert anoperator of processing system 100 if the pre-determined threshold isexceeded for a specified time period. Other example adjustments based onthe measurements provided by accelerometers are described in Table B.

In a further embodiment, sensor 212 associated with bearing assembly 206may be a strain gauge configured to determine the torque imparted by adrill pipe/tool joint interface on drill string 104 to bearing assembly206. The measured torque may indicate whether the bearings in bearingassembly 206 and/or seal element 210 are failing or worn and may becompared with a pre-determined value to determine element slippage. Ifthe measured torque is greater than a pre-determined threshold,processing system 304 may generate an alarm for display on display 306.Other example adjustments based on the measurements provided by straingauges are described in Table B.

The drilling conditions measured by sensors 212 and actions taken byprocessing system 304 that are described with respect to FIG. 3 aremerely exemplary of the drilling conditions that may be analyzed byprocessing system 304. Additional drilling conditions associated withRCD 106 may be analyzed and processing system 304 may determine furtheractions to take during drilling operations based on the analyzed data asfurther described in Table B. Additionally, processing system 304 mayanalyze multiple drilling conditions and make a determination based onthe combined data as further described in Table B. Modifications,additions, or omissions may also be made to FIG. 3 without departingfrom the scope of the present disclosure. For example, the number andtype of sensors 212 may vary depending on the drilling application.

In some embodiments, the operator may take an action based on the alarmand/or processing system 304 may automatically take the action byadjusting one or more drilling parameters. The operator mayindependently take actions that may affect the drilling conditions,determinations based on the drilling conditions, and/or automatedactions based on the drilling conditions. In some embodiments, theseactions may be done to override a feature or recommended action ofcontrol system 300 and in some embodiments may be taken by interactingwith control system 300. For example, an operator may perform one of thefollowing actions: turn drilling system 100 on or off with actuation ofa button, manually turn off a safety feature like a pressure lock forlatch assembly 103, manually open or close latch assembly 103, adjust alubrication system pressure set point from a default value, setdifferent parameters of drilling conditions for rig up, normaloperation, and/or rig down profiles (e.g. increased rates of change forpressure and temperature may be permissible during rig up and rig downwhen compared to normal operation), adjust a temperature set point froma default value affecting cooler fans turning on or off and/or heatersturning on or off, manually open or close valves, manually turn pumps onor off, reset tool joint 214 stripping count, reset a count of hours inhole (both static and/or rotating), manually turn on or off a heater,manually turn on or off a cooler fan, and/or reset a total flow countfor a flow meter or a pump-stroke counter.

Control system 300 may store any or all of the data received orprocessed at control system 300, for example, in storage device 316, andmay include time stamps of when data was received and/or processed. Forexample, control system 300 may store any of the calculated drillingconditions, calculations, and/or actions described in Tables A and B.Operator input to control system 300 may also be stored. For example, anoperator of the drilling system may enter a well and/or job name, startand end date and time, field hand name, operator comments, and/oroperator compliance with procedure-based task lists to bring a drillingsystem up, operate a drilling system, and/or bring a drilling systemdown. Control system 300 may also store independently taken operatoractions that may affect the drilling conditions, determinations based onthe drilling conditions, and/or automated actions based on the drillingconditions, and may include a time stamp of when the action was taken.Control system 300 may cause the storing to occur locally in storagedevice 316 or remotely (for example, transmitting data via wired orwireless connection to a data storage facility). In some embodiments, adata retention scheme may be in place to retain at least a portion ofstored data for at least the length of a particular drilling operationinvolving the drilling system. In some embodiments, some data may bepreferentially stored over other data, for example and in no waylimiting, triggered alarms and operator input may be stored indefinitelywhile other data may be periodically deleted from storage. It will beappreciated that any of a variety of data retention schemes may be usedin accordance with the present disclosure.

Table A illustrates example drilling conditions that may be monitored,example locations for the sensors within the drilling system or examplesources where information regarding the drilling condition may bereceived, and example sensors that may be used to measure the drillingconditions. It will be appreciated that the entries in Table A aremerely exemplary of the drilling conditions that may be measured,locations for the sensors within drilling system and types of sensorsthat may be used, and are in no way limiting. While some of the entriesin Table A may be expressed with reference to FIGS. 1-3, it will beappreciated that the entries are merely illustrative and are in no waylimiting. In addition, it will be appreciated that in addition to asingle entry for a given drilling condition, any combination of entriesfrom Table A may be utilized, including multiple entries for a singlerow. For example, in considering pressure in bearing assembly 206, theremay be a pressure transducer in the main cavity of bearing assembly 206,a combination pressure/temperature sensor in the seal pressure stage,and a pressure transducer in the cooling circuit, the combination ofwhich may facilitate the monitoring and/or measuring of pressure inbearing assembly 206. It will also be appreciated that a single sensormay measure multiple drilling conditions.

TABLE A Drilling Condition Location and Type of Sensor or Source ofInformation standpipe 118 pressure transducer within standpipe 118pressure MWD software reporting previously sensed pressure pressure offluid in pressure transducer or combination sensor (e.g. annulus 202below pressure/temperature sensor) in body 204 of RCD 106 below sealelement 210B bearing assembly 206 pressure transducer or combinationsensor (e.g. pressure/temperature sensor) upstream of a choke in annulus202 temperature of fluid in temperature transducer or combination sensor(e.g. annulus 202 below pressure/temperature sensor) in body 204 of RCD106 below seal element 210B bearing assembly 206 temperature transduceror combination sensor (e.g. pressure/temperature sensor) upstream of achoke in annulus 202 pressure in bearing pressure transducer orcombination sensor (e.g. assembly 206 pressure/temperature sensor) inmain cavity of bearing assembly 206 pressure transducer or combinationsensor (e.g. pressure/temperature sensor) between seal elements (e.g.rotary seals) where pressure may differ from wellbore pressure and mayalso differ from the pressure in the main cavity of bearing assembly 206pressure transducer or combination sensor (e.g. pressure/temperaturesensor) in cooling circuit associated with bearing assembly 206 pressuretransducer or combination sensor (e.g. pressure/temperature sensor) inincoming or return lines for drilling fluid flow rate in bearing flowmeter in main cavity of bearing assembly 206 assembly 206 fluids flowmeter in seal pressure stage flow meter in cooling circuit flow meter inlubrication circuit temperature in bearing temperature transducer orcombination sensor (e.g. assembly 206 pressure/temperature sensor) inmain cavity of bearing assembly 206 temperature transducer orcombination sensor (e.g. pressure/temperature sensor) in seal pressurestage temperature transducer or combination sensor (e.g.pressure/temperature sensor) in cooling circuit temperature transduceror combination sensor (e.g. pressure/temperature sensor) in incoming orreturn lines for drilling fluid revolutions per minute proximity sensoron fixed members of bearing assembly (RPM) of bearing 206 assembly 206proximity sensor on rotating members of bearing assembly 206 mechanicalsensor on roller contacting bearing assembly 206 mechanical sensor onarm contacting bearing assembly 206 tachometer or encoder on rotatingmembers of bearing assembly 206 RPM of drill string mechanical sensor onroller contacting drill string 104 104 mechanical sensor on armcontacting drill string 104 drilling system 100 previously sensed valuemanual entry of RPM value by an operator of drilling system 100 pressurebetween pressure transducer or combination sensor (e.g. elements (e.g.upper pressure/temperature sensor) in upper stripper stripper andmandrel pressure transducer or combination sensor (e.g. of RCD 106)pressure/temperature sensor) in mandrel pressure transducer orcombination sensor (e.g. pressure/temperature sensor) in other elementstool joint 214 count Casing Collar Locator (CCL) inside mandrel CCLinside upper stripper CCL inside body 204 CCL inside tieback proximitysensor inside mandrel proximity sensor inside upper stripper proximitysensor inside body 204 proximity sensor inside tieback distance sensorassociated with mandrel distance sensor associated with upper stripperdistance sensor associated with body 204 distance sensor associated withupper tieback mechanical sensor on roller contacting drill string 104mechanical sensor on arm contacting drill string 104 tool joint 214 CCLinside mandrel stripping rate/rate of CCL inside upper stripperpenetration CCL inside body 204 CCL inside tieback proximity sensorinside mandrel proximity sensor inside upper stripper proximity sensorinside body 204 proximity sensor inside tieback distance sensorassociated with mandrel distance sensor associated with upper stripperdistance sensor associated with body 204 distance sensor associated withupper tieback mechanical sensor on roller contacting drill string 104mechanical sensor on arm contacting drill string 104 vibration ofbearing accelerometer on mandrel assembly 206 accelerometer on housingof bearing assembly 206 proximity sensor on mandrel proximity sensor onhousing of bearing assembly 206 torque imparted from strain gauge onmandrel drill string 104 and/or strain gauge inside seal element/packertool joint 214 to mandrel and/or bearing assembly 206 latch assembly 103flow meter in hydraulic circuit engagement pressure transducer orcombination sensor (e.g. pressure/temperature sensor) in hydrauliccircuit proximity sensor in latch assembly 103 distance sensor in latchassembly 103 mechanical sensor on roller contacting latch assembly 103mechanical sensor on arm contacting latch assembly 103

Table B illustrates example interpretations of drilling conditions (forexample, those described in Table A) from the sensors within thedrilling system, example indications, parameters, or values that may bedetermined from the drilling conditions and/or interpretations, andexample actions (either automated or operator initiated) and/orconclusions that may be suggested from the drilling conditions and/orinterpretations. It will be appreciated that the entries in Table B aremerely exemplary of the interpretations, indications, parameters, orvalues that may be based on the drilling conditions from the drillingsystem, and are in no way limiting. While some of the entries in Table Bmay be expressed with reference to FIGS. 1-3, it will be appreciatedthat the entries are merely illustrative and are in no way limiting.Also, it will be appreciated that in addition to a single entry, anycombination of entries from Table B may be utilized, including multipleentries for a single row. For example, the temperature of fluid inannulus 202 below seal element 210 may be used to: indicate heat load tobe cooled by the cooling circuit, indicate whether seal element 210 isexceeding temperature limits, modify cooling circuit flow rate, open orclose additional cooling loops, activate or deactivate coolant fluidcoolers and/or chillers, indicate status of acceptable operatingtemperature, display alarm or notification if operating temperature isexceeded, or any combination thereof.

Table B

Interpretation, Conclusions, and/or Actions Based on Drilling ConditionDrilling Conditions standpipe 118 indicate status, for example, whethercirculation is in pressure progress, if a connection is being made, orif a washout or plugging is occurring pressure of fluid in indicatewhether it is safe to unlatch and activate annulus 202 below interlocks(e.g. **Inventors, what all is involved in activating seal element 210Bthe interlocks** when pressure is zero psi, indicate it is safe tounlatch and unlock system to allow unlatch operation when pressure isgreater than zero psi, indicate it is unsafe to unlatch and systemremains locked, preventing unlatch operation (e.g. software would notallow activation/actuation of the latch controls, a pressure switch maybe in a position such that power is not provided to a normally closedsolenoid valve that controls hydraulic fluid flow to activate/actuatelatch assembly 103 when pressure is greater than zero psi, hydraulicfluid flow may be prevented from activating/actuating latch assembly 103and latch assembly 103 may thereby be interlocked with the presence ofpressure in the annulus below the seal element) indicates what pressureneeds to be applied to an active element of RCD 106 indicates whatpressure needs to be applied to the lubrication system associated withRCD 106 temperature of fluid in indicate heat load to be cooled by thecooling circuit annulus 202 below indicate whether seal element 210 isexceeding seal element 210 temperature limits modify flow rate ofcoolant fluid in cooling circuit open or close additional cooling loopsactivate or deactivate coolant fluid coolers and/or chillers indicatestatus of acceptable operating temperature display alarm or notificationif operating temperature is exceeded pressure in bearing indicate ifseals and other components of lubrication assembly 206 circuits areworking properly indicate status of lubrication circuits predictlifetime of bearing assembly 206 indicate latch assembly 103 engagementdisplay alarm or notification if pressure in bearing assembly 206 notmaintained at set point flow rate in bearing indicate if cooling circuitcomponents are working assembly 206 fluids properly indicate iflubrication circuit components are working properly compare actual flowrate to set point or expected flow rates for lubrication and/or coolantfluids regulate pumps and/or valves to achieve set point flow rates forlubrication and/or coolant fluids display alarm or notification if flowrate of lubrication and/or coolant fluids outside of specified range forspecified time limit indicate if seal element 210 is worn based oncomparison of actual flow rates of lubrication and/or coolant fluids toset point or expected flow rates display alarm or notification if sealelement 210 is worn use to calculate heat transferred to cooling circuitindicate heat transfer rate (duty) of cooling circuit display alarm ornotification if heat transfer rate is below estimated required valuebased on torque, wellbore temperature, bearing assembly 206 temperature,and inlet/outlet temperatures of cooling circuit temperature in bearingindicate if temperature limits for materials of seal assembly 206element 210 or other components (e.g. o-rings) are exceeded displayalarm or notification if temperature for materials is exceeded indicatelifetime of bearings in bearing assembly 206 tool joint 214 countestimate lifetime of seal element 210 tool joint 214 display tool joint214 stripping rate stripping rate/rate of display alarm or notificationif maximum rate is penetration exceeded estimate lifetime of sealelement 210 indicate number of tool joints 214 stripped through elementand remaining lifetime (for example, in number of tool joints 214)display alarm or notification if number of tool joints 214 strippedexceeds specified value (for example, an expected element lifetime)indicate surge and swab conditions vibration of bearing estimatelifetime of bearing in bearing assembly 206 assembly 206 estimatelifetime of seal element 210 estimate other component failures (forexample, a failure causing metal-to-metal contact between rotating andstationary parts generating vibration at bearing assembly 206) indicatevibration level status based on acceptable levels display alarm ornotification if acceptable levels of vibration are exceeded forspecified duration torque imparted from indicate bearing in bearingassembly 206 failure drill string 104 and/or estimate lifetime ofbearing in bearing assembly 206 tool joint 214 to indicate seal element210 failure mandrel and/or estimate lifetime of seal element 210 bearingassembly 206 indicate element slippage or wear display alarm ornotification if specified maximum value is exceeded latch assembly 103flow meter in hydraulic circuit engagement estimate piston positionbased on amount of fluid flow through hydraulic circuit indicatepiston/latch assembly 103 position activate appropriate control profilebased on position of piston/latch assembly 103 (for example, if in an“unlatching/unlatched” position, the cooling circuit, active element,and lubrication circuit may be disabled from allowing fluid to flow toRCD 106; if in “latched/normal operation” position, the cooling circuit,active element, and lubrication circuit may be enabled to allow fluid toflow to RCD 106) pressure transducer or combination sensor (for example,pressure/temperature sensor) in hydraulic circuit indicate bearingassembly 206 is landing in body 204 based on initial pressure spikeindicate latch assembly 103 engagement when increased pressure holdsactivate appropriate control profile based on estimated location oflatch assembly 103 (for example, if latch assembly 103 is not engaged,then in an “unlatching/unlatched” position and the cooling circuit,active element, and lubrication circuit may be disabled from allowingfluid to flow to RCD 106; if latch assembly 103 is engaged, then in a“latched/normal operation” position and the cooling circuit, activeelement, and lubrication circuit may be enabled to allow fluid to flowto RCD 106) proximity sensor in latch assembly 103, distance sensor inlatch assembly 103, mechanical sensor on roller contacting latchassembly 103, and/or mechanical sensor on arm contacting latch assembly103 indicate piston/latch assembly 103 position activate appropriatecontrol profile based on position of piston/latch assembly 103 (forexample, if in an “unlatching/unlatched” position, the cooling circuit,active element, and lubrication circuit may be disabled from allowingfluid to flow to RCD 106; if in a “latched/normal operation” position,the cooling circuit, active element, and lubrication circuit may beenabled to allow fluid to flow to RCD 106) combination of indicate sealelement 210 failure if pressure between pressure between elements (e.g.upper stripper and mandrel of RCD 106) elements (e.g. upper increaseswhen tool joint 214 is not in proximity of the stripper and mandrelmandrel of RCD 106), pressure indicate status of seal element 210 offluid in annulus display alarm or notification if seal element 210 fails202 below seal element 210B, and tool joint 214 location combination ofindicate effectiveness of cooling circuit temperature of fluid in modifyflow rate of coolant fluid in cooling circuit annulus 202 below open orclose additional cooling loops seal element 210B and activate ordeactivate coolant fluid coolers and/or chillers temperature insidebearing assembly 206 combination of predict lifetime of bearing assembly206 pressure in bearing indicate estimated remaining lifetime of bearingassembly 206 and assembly 206 temperature in bearing display alarm ornotification if bearing assembly 206 assembly 206 lifetime reachesminimum value calculate upper seal element 210A leakage rate indicateupper seal element 210A leakage display alarm or notification if upperseal element 210A leakage rate exceeds set point combination ofcalculate lower seal element 210B leakage rate pressure in bearingindicate lower seal element 210B leakage assembly 206, display alarm ornotification if lower seal element 210B temperature in bearing leakagerate exceeds set point assembly 206, and pressure of fluid in annulus202 below seal element 210B combination of indicate if seal element 210is worn pressure in bearing indicate if lubrication system is workingproperly assembly 206, and display alarm or notification if set point ofpressure in pressure of fluid in bearing assembly 206 at differentialabove wellbore pressure annulus 202 below is not maintained for certaintime period seal element 210B indicate if pressure inside bearingassembly 206 should be increased or decreased regulate flow rate oflubrication fluid through lubrication system to bearing assembly 206 tomaintain pressure in bearing assembly 206 at set point combination ofindicate amount of heat being transferred into cooling cooling circuitinlet circuit from bearing assembly 206 temperature and outlet indicateheat transfer rate of cooling circuit temperatures display alarm ornotification if heat transfer rate is below estimated required valuebased on torque, wellbore temperature, bearing assembly 206 temperature,and inlet/outlet temperatures of cooling circuit combination of indicateelement slippage and if element is worn revolutions per minute estimatelifetime of seal element 210 (RPM) of bearing estimate lifetime ofbearing in bearing assembly 206 assembly 206 and estimate lifetime ofother elements RPM of drill string display RPM of bearing assembly 206,RPM of drill 104 string 104, and difference between two values displayalarm or notification if difference exceeds specified limit forspecified duration combination of indicate lifetime of elementtemperature and display available element lifetime based on movingpressure profile of average of current conditions service, length ofdisplay alarm or notification if available element lifetime exposuretime, is below specified limit slippage, number of display availableelement lifetime based on cumulative tool joints 214 average ofconditions stripped, and stripping display alarm or notification ifavailable element lifetime rate is below specified limit indicatelifetime of bearing in bearing assembly 206 display available bearinglifetime based on moving average of current conditions display alarm ornotification if available bearing lifetime is below specified limitdisplay available bearing lifetime based on cumulative average ofconditions display alarm or notification if available bearing lifetimeis below specified limit combination of indicate lifetime of sealelement 210 temperature and display available seal element 210 lifetimebased on pressure profile of moving average of current conditionsservice, length of display alarm or notification if available sealelement exposure time, torque, 210 lifetime is below specified limit andprofile of lifetime display available seal element 210 lifetime based onof bearing in bearing cumulative average of conditions assembly 206display alarm or notification if available seal element 210 lifetime isbelow specified limit

FIG. 4 illustrates a flow chart of an example method for monitoringdrilling conditions associated with a rotating control device duringdrilling operations in accordance with some embodiments of the presentdisclosure. The method is described as being performed by sensors 212described with respect to FIG. 2 and processing system 304 describedwith respect to FIG. 3, however, any other suitable system, apparatus ordevice may be used. Generally, sensors 212 may be associated withstandpipe 118 and/or with RCD 106 to measure various drilling conditionsduring drilling operations. The drilling conditions may include, but arenot limited to, strain, pressure, temperature, flow rate, position,distance and vibration. The measured values for the various drillingconditions may be analyzed by processing system 304 in order to make adetermination of what action may be taken during drilling operations. Ifprocessing system 304 determines that an action should be taken,processing system 304 may generate an alarm to alert an operator ofdrilling system 100. On the other hand, if processing system 304determines no action should be taken, drilling operations may continue.

Method 400 may start, and at step 402, sensors 212 may measure one ormore drilling conditions associated with RCD 106 during drillingoperations. The drilling conditions may include, but are not limited to,pressure, temperature, flow rate, vibration, position, torque, strainand tool joint count. As described above and in Table B, these drillingconditions may be used to determine various actions that can be takenduring drilling operations.

At step 404, sensors 212 may communicate the detected drillingconditions to processing system 304 that is configured to receivemeasurements from sensors 212 during drilling operations. In someembodiments, data representing the drilling conditions may becommunicated from sensors 212 to input device 302 usingtransmitters/receivers in various locations of a drilling system (e.g.,drilling system 100 as shown in FIG. 1). The locations may include, butare not limited to, (i) body 204, bearing assembly 206, tie back andupper stripper of RCD 106, (ii) the hydraulic power unit (HPU), (iii)the work platform, the control console and the rig floor of the drillingunit, such drilling unit 102 of FIG. 1, and (iv) near the wellhead. Inother embodiments, the data from sensors 212 may be communicated throughwires, such as electrical wires or fiber optics. In additionalembodiments, communication of the drilling conditions from sensors 212may be wireless. For example, the signals carrying the drillingconditions may be acoustic, electromagnetic or optical. The measurementsmay be communicated by sensors 212 either continuously or based on apre-determined time interval.

At step 406, processing system 304 may analyze the data associated withthe drilling conditions detected by sensors 212. In one embodiment,processing system 304 may compare the detected drilling conditions to apre-determined threshold. If the detected drilling condition is above orbelow the pre-determined threshold, depending on the particular drillingcondition, processing system 304 may determine an action that may betaken. The comparison to the pre-determined threshold may be based on asingle measurement of the particular drilling condition or a change(either an increase or decrease) in the drilling condition over time.Additionally, processing system 304 may analyze the data based on onedrilling condition or a combination of several drilling conditions. Insome embodiments, the detected drilling conditions may be used tocalculate the estimated lifetime of seal element 210 and/or the bearingsof bearing assembly 206 during the drilling operations. Other examplesof how processing system 304 may analyze the measured data are describedin Table B.

At step 408, processing system 304 may determine whether an actionshould be taken based on the analyzed data. If processing system 304determines that no action should be taken, drilling operations maycontinue at step 410 and method 400 may return to step 402 to continuemeasuring the drilling conditions. If processing system 304 determinesthat an action should be taken, processing system 304 may generate analarm to alert an operator of drilling system 100 at step 412. Examplealarms that may be generated are described in Table B. At step 414, theoperator may take an action based on the alarm and/or processing system304 may automatically take the action by adjusting one or more drillingparameters. Example actions that may be taken by either the operatorand/or processing system 304 are described in Table B.

Modifications, additions, or omissions may be made to method 400 withoutdeparting from the scope of the present disclosure. For example, theorder of the steps may be performed in a different manner than thatdescribed and some steps may be performed at the same time.Additionally, each individual step may include additional steps withoutdeparting from the scope of the present disclosure.

FIG. 5 illustrates a flow chart of an alternative example method formonitoring drilling conditions associated with a drilling system inaccordance with some embodiments of the present disclosure. The methodis described as being performed by sensors 212 described with respect toFIG. 2 and control system 300 described with respect to FIG. 3, however,any other suitable system, apparatus or device may be used. Generally,sensors 212 may be associated with standpipe 118 and/or with RCD 106 tomeasure various drilling conditions during drilling operations. Thedrilling conditions may include, but are not limited to, strain,pressure, temperature, flow rate, position, distance and vibration. Inaddition, other various sources of information regarding a drillingsystem may be provided, for example, from a MWD system. The measuredvalues for the various drilling conditions may be analyzed by processingsystem 304 in order to make a determination of whether an alarm shouldbe generated and an action taken.

Method 500 may start, and at step 502, sensor 212 may measure a drillingcondition associated with a drilling system (e.g., drilling system 100as illustrated in FIG. 1). The drilling condition may include, but isnot limited to, pressure, temperature, flow rate, vibration, position,torque, strain and tool joint count.

At step 504, sensor 212 may communicate the detected drilling conditiondata to processing system 304 that is configured to receive measurementsfrom sensors 212. In some embodiments, data representing the drillingconditions may be communicated from sensors 212 to input device 302using transmitters/receivers in various locations of a drilling system(e.g., drilling system 100 as shown in FIG. 1). The locations mayinclude, but are not limited to, (i) body 204, bearing assembly 206, tieback and upper stripper of RCD 106, (ii) the hydraulic power unit (HPU),(iii) the work platform, the control console and the rig floor of thedrilling unit, such drilling unit 102 of FIG. 1, and (iv) near thewellhead. In other embodiments, the data from sensors 212 may becommunicated through wires, such as electrical wires or fiber optics. Inadditional embodiments, communication of the drilling conditions fromsensors 212 may be wireless. For example, the signals carrying thedrilling conditions may be acoustic, electromagnetic or optical. Themeasurements may be communicated by sensors 212 either continuously orbased on a pre-determined time interval.

At step 506, processing system 304 may store the raw drilling conditiondata. For example, processing system 304 may store the raw drillingcondition data in storage device 316 local to the drilling system. Insome embodiments, processing system 304 may store the raw data in astorage device remote from the drilling system. This may be facilitatedby outputting the raw drilling condition data through outputs 310 to aremote location. For example, processing system 304 may use outputs 310to transmit the raw drilling condition data wireless to a storagefacility remote from the drilling system. The raw drilling conditiondata may be stored with a time stamp, an identification of sensor 212,identification of the drilling system, and/or other identifyinginformation.

At step 508, processing system 304 may determine whether the rawdrilling condition data is usable when processed using a scalar functionor some type of algorithm. For example, if the drilling condition is oneof temperature, pressure, flow rate, vibration, latch position, ortorque, processing system 304 may process the raw drilling conditiondata using a scalar function. In some embodiments, processing system 304may use raw position data from proximity sensors, distance sensors, ormechanical sensors to calculate revolutions per minute (RPM) of bearingassembly 206 and/or drill string 104 and tool joint stripping rate orrate of penetration (ROP) using an algorithm.

At steps 510 and 512, processing system 304 processes the receiveddrilling condition using the appropriate processing scheme. For example,at step 510, a scalar function may be used to process raw the drillingcondition data to produce processed drilling condition data. In someembodiments, at step 512 processing system 304 may processes thereceived raw drilling condition data using an algorithm to produceprocessed drilling condition data.

At step 514, processing system 304 may store the processed drillingcondition data. This may be stored in a similar manner to the rawdrilling condition data stored at step 506. For example, the processeddrilling condition data may be stored locally to drilling system instorage device 316 or may be stored in a remote facility.

At step 516, processing system 304 may determine whether a desiredfactor, factor i, may be based on a combination of drilling conditionsor if a single drilling condition is used to determine the desiredfactor. A factor may include processed drilling condition data, forexample, raw pressure drilling condition data processed using a scalarfunction, or as another example, raw position data processed using analgorithm to determine RPM of bearing assembly 206. A factor may alsoinclude any of the other calculated, estimated, or determinedinformation as described in Table A or Table B, for example, expectedlifetime of bearings in bearing assembly 206, or heat being transferredto a cooling circuit. If it is determined that the given desired factoruses a single drilling condition, method 500 may proceed to step 520. Ifit is determined that the given desired factor may be based on more thanone, or in other words, a combination of drilling conditions to bedetermined, method 500 may proceed to step 518.

At step 518, processing system 304 may determine if all processeddrilling conditions used to determine factor i have been received. Forexample, if the desired factor i was the lifetime of a bearing inbearing assembly 206, pressure inside bearing assembly 206 andtemperature inside bearing assembly 206 may both be utilized todetermine factor i. Thus, in this example, processing system 304 maydetermine if both pressure and temperature inside bearing assembly 206were received and processed. If less than all of the drilling conditionsused to determine factor i have been received, method 500 may return tothe start of the method to repeat the steps to receive and processadditional drilling conditions until all of the drilling conditions havebeen received and processed to determine desired factor i. If all of thedrilling conditions used to determine factor i have been received,method 500 may proceed to step 520. At step 520, processing system 304may determine factor i based on the processed drilling condition(s).

At step 522, processing system 304 may determine whether factor i haspassed a trigger point, or in other words, whether the value determinedfor factor i has dropped below or gone above a pre-determined thresholdvalue. If it is determined that factor i has not passed the triggerpoint, method 500 may return to the start of the method. If it isdetermined that factor i has passed the trigger point, method 500 maycontinue to step 524.

At step 524, processing system 304 may determine whether factor i waitsto trigger an alarm until factor i is past the trigger point for acertain duration of time before an alarm is generated. For example, asdescribed in Table B, if factor i is the slippage of elements based onRPM of drill string 104 and RPM of bearing assembly 206, an alarm may bedisplayed when the difference between the two RPMs exceeds a specifiedlimit for a specified duration. If it is determined that factor i doesnot wait until the value of factor i is past the trigger point for agiven duration to generate an alarm, method 500 may proceed to step 528.If it is determined that factor i waits until the value of factor i ispast the trigger point for a given duration to generate an alarm, method500 may proceed to step 526. At step 526, processing system 304determines whether the given duration of time has been exceeded. If theduration of time has been exceeded, method 500 may proceed to step 528.If the duration of time has not been exceeded, method 500 may return tothe start of method 500.

At step 528, processing system 304 may generate an alarm. For example,the alarm may be displayed on display 306 or may be printed at printer308. At step 530, processing system 304 may store the alarm that isgenerated. This may be stored in a similar manner to the storageperformed at steps 506 and/or 514. For example, alarm may be storedlocally to the drilling system and/or stored remotely. As an additionalexample, the generated alarm may be stored with a time stamp or otheridentifying information.

At step 532, processing system 304 may determine whether an action isadvisable based on the generated alarm. For example, if the alarmindicates that a cooling circuit should increase the flow rate of thecooling fluid, processing system 304 may output a signal to the coolingcircuit directing it to increase the flow rate of the cooling fluid. Ifan action is not advisable, method 500 may return to the start of method500. If an action is advisable, method 500 may proceed to step 534 toperform an automated action to address the generated alarm. Someexamples of automated actions that may be taken are disclosed in TableB. It will be appreciated that an operator of the drilling system maytake an action based on the alarm which has been generated.

Modifications, additions, or omissions may be made to method 500 withoutdeparting from the scope of the present disclosure. For example, theorder of the steps may be performed in a different manner than thatdescribed and some steps may be performed at the same time.Additionally, each individual step may include additional steps withoutdeparting from the scope of the present disclosure.

Although the present disclosure and its advantages have been describedin detail, it should be understood that various changes, substitutionsand alterations can be made herein without departing from the spirit andscope of the disclosure as defined by the following claims.

What is claimed is:
 1. A drilling system, comprising: a rotating controldevice (RCD); a plurality of sensors included in or in proximity to theRCD, each of the sensors configured to detect a drilling conditionassociated with the RCD during a drilling operation; and a controlsystem configured to determine an adjustment to a drilling parameterduring drilling operations based on the detected drilling conditions. 2.The drilling system of claim 1, wherein the detected drilling conditionsare selected from the group consisting of pressure, temperature, flowrate, vibration, position, torque, strain and tool joint count.
 3. Thedrilling system of claim 1, wherein the sensors are selected from thegroup consisting of a pressure transducer, a temperature transducer, athermocouple, a proximity sensor, a distance sensor, an accelerometerand a strain gauge.
 4. The drilling system of claim 1, wherein thesensors are included in or in proximity to a seal element of the RCD. 5.The drilling system of claim 4, wherein the seal element comprises aplurality of seals and each of the plurality of seals is included in orin proximity to at least one of the plurality of sensors.
 6. Thedrilling system of claim 4, wherein the control system is furtherconfigured to calculate an estimated lifetime of the seal element basedon the detected drilling conditions.
 7. The drilling system of claim 1,wherein the sensors are included in or in proximity to a bearingassembly of the RCD.
 8. The drilling system of claim 7, wherein thecontrol system is further configured to calculate an estimated lifetimeof bearings in the bearing assembly based on the detected drillingconditions.
 9. The drilling system of claim 7, wherein the controlsystem is further configured to calculate revolutions per minute of thebearing assembly based on the detected drilling conditions.
 10. Thedrilling system of claim 7, wherein the control system is furtherconfigured to calculate rate of penetration of the drill string based onthe detected drilling conditions.
 11. The drilling system of claim 1,wherein the sensors are included in or in proximity to a latch assemblyof the RCD.
 12. The drilling system of claim 11, wherein the controlsystem is further configured to determine engagement of latch assemblybased on the detected drilling conditions.
 13. The drilling system ofclaim 1, wherein one of the plurality of sensors is included in or inproximity to a casing collar locator (CCL).
 14. A method comprising:measuring a plurality of drilling conditions by a plurality of sensorsincluded in or in proximity to a rotational control device (RCD) of adrilling system during drilling operations; communicating the pluralityof drilling conditions to a processing system; analyzing the drillingconditions by the processing system; generating an alarm based on theanalyzed drilling conditions; and adjusting a drilling parameter basedon the alarm.
 15. The method of claim 14, wherein the drilling parameteris adjusted by an operator of the drilling system.
 16. The method ofclaim 14, wherein the drilling parameter is automatically adjusted bythe processing system.
 17. The method of claim 14, further comprisingstoring at least one of the drilling conditions communicated to theprocessing system and the alarm.
 18. The method of claim 17, wherein theat least one of the drilling conditions communicated to the processingsystem and the alarm are stored with a time stamp.
 19. A rotationalcontrol device comprising: a body including a first sensor; a sealelement configured to seal an annulus between the body and a drillstring of a drilling system, the seal element including a second sensor;and a bearing assembly coupled to the seal element to facilitate motionof the drill string relative to the body, the bearing assemblycomprising a third sensor.
 20. The rotational control device of claim19, further comprising a latch assembly, the latch assembly comprising afourth sensor and a remotely operable hydraulic clamp or latch toselectively secure and release the bearing assembly relative to thebody.